In situ process to recover heavy oil and bitumen

ABSTRACT

An in situ reservoir recovery process consisting of a horizontal injection well and a horizontal production well to extract bitumen or heavy oil from a reservoir. The process consists of a first phase operated at high-pressure in which steam, hydrocarbon solvent and non-condensable gases are injected into the reservoir and a second phase in which the injected fluids are transitioned to a high content of solvent and non-condensable gas and a reduced amount of steam to maintain a warm zone in the neighbourhood of the injection and production wells. The steam injection is sufficient to promote vapor transport of the solvent into the vapor depletion chamber and maintain the process at elevated temperatures in order to maintain low fluid viscosities in the production wellbore and to achieve preferred phase behaviour of the solvent hydrocarbon and the heavy oil or bitumen. The operating pressure of the process is controlled to prevent losses of the solvent hydrocarbon to the formation and to aid in solvent production to the production well in order for future re-cycling.

FIELD OF THE INVENTION

The present invention relates to a method to improve heavy oil and/orbitumen recovery from a hydrocarbon reservoir. The invention, inparticular, relates to a process in which steam, solvent andnon-condensable gas injection rates and pressure into an injection wellare phased throughout the process to achieve improved thermalefficiency, mobilization of heavy oil and/or bitumen within thehydrocarbon reservoir and improved solvent recovery.

BACKGROUND OF THE INVENTION

There are many methods that are used to recover in situ heavy oil orbitumen from oilsands reservoirs. Typically, in situ methods are used inheavy oil or bitumen deposits that are greater than about 70 m deepwhere it is no longer economic to recover the hydrocarbon by currentsurface mining technologies. Depending on the operating conditions ofthe in situ process and the geology of the heavy oil or bitumenreservoir, in situ processes can recover between about 25 and 75% of theinitial hydrocarbon in the reservoir. For most heavy oil or bitumenrecovery processes, the focus of the process is to reduce the in situviscosity of the heavy oil or bitumen so that its mobility rises to asufficient amount so that it can flow from the reservoir to a productionwellbore. The reduction of the in situ heavy oil or bitumen can beachieved by raising the temperature and/or dilution with solvent whichis the typical practice in existing processes for recovering heavy oilor bitumen.

The Steam Assisted Gravity Drainage (SAGD), as described in U.S. Pat.No. 4,344,485, issued Aug. 17, 1982, to Butler, is a relatively popularin situ recovery method which uses two horizontal wells positioned inthe reservoir to recover hydrocarbons. In this process, the two wellsare drilled substantially parallel to each other by using directionaldrilling. The bottom well is the production well and is typicallylocated just above the base of the reservoir. The top well is theinjection well and is located roughly between 5 and 10 m above theproduction well. The top well injects steam into the reservoir from thesurface. In the reservoir, the injected steam flows from the injectionwell and forms a vapor phase steam chamber that as the process evolvesgrows vertically until it reaches the top of the reservoir. The steamloses its latent heat to the cool heavy oil or bitumen at the edges ofthe steam chamber and as a result raises the temperature of the heavyoil or bitumen. The viscosity of the heated heavy oil or bitumen at thechamber edge drops and flows under gravity down the edges of the chambertowards the production wellbore located below the injection well. Thefluids that enter the wellbore are moved, either by natural pressureforces or by pump, to the surface. The thermal efficiency of SAGD isreflected in the steam (expressed as cold water equivalent) to oil ratio(SOR) that is CWE m3 steam/m3 oil. Typically, a process is consideredthermally efficient if its SOR is between 2 and 3 or lower. There isextensive published literature concerning the successful design andoperation of SAGD. The literature reveals that while SAGD appears to betechnically effective at producing heavy oil or bitumen to the surface,there is a continued need for processes that improve the SOR of SAGD.The major capital and operating costs of SAGD involve the facilities togenerate steam and re-cycle produced water back to the steam generators.Additionally, there is a need to design processes that improve thecapital and operating costs of SAGD.

An extension of SAGD is the Steam and Gas Push (SAGP) process developedby Butler (Thermal Recovery of Oil and Bitumen, Grav-Drain Inc.,Calgary, Alberta, 1997). In the SAGP process, steam and anon-condensable gas are co-injected into the reservoir. It is believedthat the non-condensable gas provides an insulating layer at the top ofthe steam chamber that improves the thermal efficiency of the process.At present, it remains unclear what the optimal amount ofnon-condensable gas that should be added to the injected steam.

Examples of published literature describing drainage rates for SAGD infield operations include: Butler (Thermal Recovery of Oil and Bitumen,Grav-Drain Inc., Calgary, Alberta, 1997), Komery et al. (Paper 1998.214,Seventh UNITAR International Conference, Beijing, China, 1998),Saltuklaroglu et al. (Paper 99-25, CSPG and Petroleum Society JointConvention, Calgary, Canada, 1999), Butler et al. (J. Can. Pet. Tech.,39(1): 18, 2000).

There are other examples of the processes that use combinations of steamand solvents to recover heavy oil.

U.S. Pat. No. 4,519,454, issued May 28, 1985, to McMillen teaches whatis essentially a cyclic thermal-solvent process which consists of firststeam heating the reservoir to raise the temperature by 40-200° F.(22-111° C.) and second producing the reservoir fluids directly afterheating. In the heating stage, the injection temperature is kept belowthe coking temperature. The production interval continues until steamproduction occurs after which liquid solvent is injected into theinjection well so that an oil-solvent mixture is produced. At somepoint, steam injection re-commences and another cycle of the processstarts.

Another example is seen in U.S. Pat. No. 4,697,642, issued Oct. 6, 1987,to Vogel which describes a steam and solvent flooding process in whichsteam and vaporized solvent are injected in a stepwise manner to lowerthe viscosity of in situ hydrocarbons to aid their production to thesurface. Vogel teaches that the choice of solvent is not consideredcritical and suggests that the solvent should be a light, readilydistillable liquid, such as gasoline, kerosene, naphtha, gas wellcondensates, benzene, toluene, distillates, that is miscible with the insitu hydrocarbons. There are two issues about this process: first theprocess uses high solvent to hydrocarbon ratio and second the solventsare typically more valuable than the produced hydrocarbon. Both of theseissues adversely impact process economics.

In an extension of SAGD, Palmgren (SPE Paper 30294, 1995) describes aprocess where high temperature naphtha replaces steam in the SAGDprocess. However, given the value of naphtha, a substantial amount ofthe injected naphtha is required to be recovered for the process to beeconomic and compete with SAGD. A similar extension of SAGD which usessolvent, called Vapor Extraction (VAPEX), has been proposed as acommercial alternative to SAGD. VAPEX, similar to SAGD, consists of twohorizontal wells positioned in the reservoir. The top well is theinjection well whereas the bottom well is the production well. In VAPEX,a gaseous solvent (for example ethane, propane, or butane) is injectedinto the reservoir instead of steam. The injected solvent condenses andmixes with the heavy oil or bitumen and reduces its viscosity. Under theaction of gravity, the mixture of solvent and bitumen flow towards theproduction well and are produced to the surface. Due to absence of steamgeneration and water handling facilities, capital costs associated withVAPEX facilities are lower than that of SAGD. However, it is unclear howinterwell communication is to be established and how the process is tobe operated in order to make the process economic. Also there areunresolved issues on how to prevent significant solvent losses to thereservoir which will be vitally important for economic success of theprocess. Additionally, the operating pressure range of VAPEX is limitedbecause of required condensation of the injected gaseous solvent at theedges of the vapor chamber. In several papers, Butler and Mokrys (J.Can. Pet. Tech., 30(1): 97, 1991; J. Can. Pet. Tech., 32(6): 56, 1994)documented a version of VAPEX which uses hot water and solvent vapor,for example propane, near its dew point in an experimental Hele-Shawcell to recover heavy oil. The solvent vapor fills the vapor chamber andat the chamber edges, the solvent dissolves into the heavy oil loweringthe oil phase viscosity. The reduced-viscosity oil flows at the chamberedges to the production well located at the bottom of the formation.Butler and Mokrys, supra, describe that the solvent is co-injected withhot water to raise the reservoir temperature by between 4° and 80° C.The hot water also re-vaporizes some of the solvent from the heavy oilto create refluxing and additional utilization of the solvent. Butler,in U.S. Pat. No. 5,607,016, issued Mar. 4, 1997, to Butler, discloses avariant of VAPEX for recovering hydrocarbons in reservoirs that arelocated on top of an aquifer. A non-condensable displacement gas isco-injected with a hydrocarbon solvent at sufficient pressure to limitwater ingress into the recovery zone. Butler and Jiang (J. Can. Pet.Tech., 39(1): 48, 2000) describe means to manage VAPEX in the field. Ina paper, Luhning et al. (CHOA Conference, Calgary, Canada, 1999)describe the economics of VAPEX.

In a solvent-aided process, Canadian Patent No. 1,059,432 (Nenninger)discloses a method in which sub-critical solvent gas maintained justbelow its saturation pressure, such as ethane or carbon dioxide, isinjected into the reservoir to lower the viscosity of heavy oil.

In U.S. Pat. No. 5,899,274, issued May 4, 1999, to Frauenfeld et al., amethod is described that mobilizes heavy oil by using a vapor mixture ofat least two solvents whose dew point corresponds to the reservoirtemperature and pressure. The main concern with this process is that thesolvent mixture has to be adjusted to fit the reservoir temperature andpressure.

Canadian Patent Number 2,323,029, issued Mar. 16, 2004, to Nasr et al.,describes the Expanding Solvent-SAGD (ES-SAGD) method that comprisescontinuously co-injecting steam and an additive (one or a combination ofC1 to C25 hydrocarbons and carbon dioxide) into the reservoir. Theadditive is chosen so that its saturation temperature is in the range ofabout ±150° C. of the steam temperature at the operating pressure. Afterinjection, a fraction of the additive changes from vapor to liquid phasein the reservoir. This patent teaches that the additive concentration inthe injected stream is between about 0.1% and about 5% liquid volume.

In Canadian Patent Number 2,325,777, issued May 27, 2003, to Gutek etal., a thermal-solvent process is disclosed called the Steam and VaporExtraction Process (SAVEX). This process has two stages. First, steam isinjected into an upper horizontal well until the top of the steamchamber is between about 25 to 75% of the distance from the injectionwell to the top of the reservoir or the production rate of hydrocarbonsfrom the reservoir is about 25 to 75% of the peak rate anticipated fromthe SAGD process. Second, a solvent is injected in vapor phase into thesteam chamber. The solvent helps to reduce the viscosity of the heavyoil or bitumen and permits additional recovery of heavy oil or bitumen.

Canadian Patent Application Number 2,391,721, issued Jun. 26, 2002, toNasr, teaches a thermal-solvent process, referred to as the TaperedSteam and Solvent-SAGD (TSS-SAGD) process, in which a steam and/or hotwater and a solvent (C1 to C30 hydrocarbons, carbon dioxide; carbonmonoxide and associated combinations) is injected into the heavy oilreservoir. Initially, the injectant composition has steam andwater-to-solvent volume ratio greater than or equal to about 1. As theprocess evolves, the steam and water-to-solvent volume ratio is lowered,at least once, to a different steam and water-to-solvent volume ratiogreater than or equal to about 1. The injected volume ratio of steam andliquid water-to-solvent is reduced as the process evolves.

The literature contains many examples of attempts to recover in situheavy oil or bitumen economically yet there is still a need for morethermally-efficient and cost-effective in situ heavy oil or bitumenrecovery technologies. The present invention provides a method torecover heavy oil and/or bitumen from an underground reservoir in amanner that is more thermally efficient and cost effective than presentmethods.

SUMMARY OF THE INVENTION

The invention relates generally to a process to recover hydrocarbonsfrom an underground reservoir.

One object of one embodiment of the present invention is to provide amethod for recovering heavy hydrocarbons from an underground reservoircontaining heavy hydrocarbons, an injection well and a production well,comprising injecting steam and optionally at least one ofnon-condensable gas and hydrocarbon solvent into the reservoir,receiving produced hydrocarbons within the production well,progressively adjusting the volume of the steam, the non-condensable gasand hydrocarbon solvent injected into the reservoir, whereby thehydrocarbon solvent and non-condensable gas are predominant relative tothe volume of the steam, and recovering further produced heavyhydrocarbons.

In one embodiment of the invention, a method is provided to extractheavy oil or bitumen from a reservoir located underground. The reservoiris penetrated by a horizontal wellpair that comprise a top injectionwell and a bottom production well both being substantially parallel toeach other. In the method, steam, solvent, and non-condensable gas areinjected through the injection well into the reservoir over time whilereservoir fluids are produced through the production well. The injectedfluids enter a vapor chamber that surrounds and extends above theinjection well. In the present invention, the injection rates andinjection pressure are controlled in order to minimize heat losses tothe overburden and maximize the action of the solvent in reducing theviscosity of the heavy oil and/or bitumen. Additionally, the operatingpressure is controlled together with the relative amounts of steam,solvent, and non-condensable gas to maximize the solvent recovery fromthe process. The partial pressure of the solvent is controlled in thevapor chamber as the process is evolved.

The solvent may be a hydrocarbon solvent that consists of one or acombination of the C3+ hydrocarbons or any of the components that maynormally be found in gas condensates or diluent. The non-condensable gasmay include nitrogen gas, natural gas methane, carbon dioxide, or theflue gas that results from the combustion of a fuel.

The recovery method may include the additional step of adjusting theinjection pressure and relative amounts of steam, solvent, andnon-condensable gas to control the vapor chamber temperature to enhancethe solubility of solvents.

In an embodiment, the method may include recovering additional solventand heavy oil or bitumen from the reservoir during a blowdown stage atthe end of the process.

A further object of one embodiment of the present invention is toprovide a method for recovering heavy hydrocarbons from an undergroundreservoir containing heavy hydrocarbons, an injection well and aproduction well, comprising injecting steam into the reservoir, to forma steam vapor chamber, co-injecting predetermined quantities of steam,hydrocarbon solvent and non-condensable gas into the steam vapor chamberto maximize the solubility of the solvent in the heavy hydrocarbons,recovering produced hydrocarbons through the production well, adjustingthe volume of steam injected into the vapor chamber to be subordinate tothe volume of hydrocarbon solvent and non-condensable gas wherebypartial pressure of the steam in the chamber is reduced and hydrocarbonsolvent solubility is elevated in the heavy hydrocarbons, and recoveringfurther produced hydrocarbons through the production well.

Having thus generally described the invention, reference will now bemade to the accompanying drawings illustrating preferred embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a side view of a reservoir and horizontally drilled wellsduring the initial start up phase of the process;

FIG. 1B is a cross-section of FIG. 1A;

FIG. 2 is a graph showing a sample injection profile conforming to theprocess;

FIG. 2A is a graph showing a sample injection pressure profileconforming to the process;

FIG. 3A is a side view of a reservoir and horizontally drilled wellsduring the second phase of the process;

FIG. 3B is a cross-section of FIG. 3A;

FIG. 4 is a graph of the energy requirements of the SAGD, ES-SAGD, andprocesses as indicated by the cumulative steam to oil ratio over thetime of production;

FIG. 5 is a graphical representation comparing bitumen recovery of theSAGD, ES-SAGD, and processes as a function of time;

FIG. 6 is a graphical representation comparing cumulative solventrecovery of the ES-SAGD, and processes as a function of time.

Similar numerals denote similar elements.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

With reference to the Figures, a phased heating and solvent enhancedrecovery process for recovery of in situ bitumen or heavy oil isdescribed. Broadly, the invention consists of a sequence of fluidinjection and operating pressure changes that results in significantlyimproved heavy oil or bitumen production from a heavy oil or bitumenreservoir.

Heavy oil and bitumen is a more viscous material compared to light oilsat in situ initial reservoir temperatures and pressures. Also, atelevated temperatures, heavy oil and bitumen has higher viscosity thanlighter hydrocarbons such as solvent at the same temperature. At evenmore elevated temperatures, even though heavy oil and bitumen remains inliquid state, the solvent can be in the gaseous state and freely movethroughout the reservoir providing there is a driving pressure gradientto motivate the solvent motion. The amount of solvent that can dissolvein heavy oil or bitumen depends on the reservoir temperature andpressure. There are two means to deal with the effectiveness of a heavyoil or bitumen solvent to produce heavy oil or bitumen to a productionwellbore: first, the solvent must be chosen to substantially match thereservoir pressure and temperature to maximize its effectiveness in thetargeted heavy oil or bitumen and second, change the operatingconditions, i.e. the operating pressure and temperature, in order tocontrol the solvent effectiveness in the heavy oil or bitumen. Thetemperature of the depletion zone from which heavy oil and bitumen arebeing extracted can be controlled by injecting saturated steam into theformation.

In gravity-drainage processes, there is a requirement to form a vaporchamber in the reservoir. This is to produce the density contrastbetween the vapor and liquid which allows the gravity-induced flow ofliquid to the lower portion of the vapor chamber where a production wellis located. The production well then removes the liquid from the chamberand carries it to the surface. The heavy oil and bitumen drains at theedges of the chamber, expanding the chamber in the reservoir. It is alsorequired to expand the chamber to ensure that fresh heavy oil andbitumen is accessed by injected steam and solvent as the process evolvesand to manage the operating pressure in the chamber so that solventcarried to the chamber edge mixes and dissolves in the heavy oil andbitumen so that the viscosity of the heavy oil and bitumen is reduced.

It should be noted that when referring to volumes of solvent, volumesare specified as the ratio of liquid hydrocarbon solvent to total liquidinjected, and steam volume is expressed in terms of the volume of coldwater required to produce the steam volume. In accordance with thisinvention, as shown in FIGS. 1A and 1B, a horizontal production well 10is drilled into a reservoir 12 penetrating the surface of the earth 14and the overburden 16. The reservoir 12 is bounded by the bottom of theoverburden 16 and the top of understrata 18. Above the reservoir 12 isoverburden 20 which consists of any one or more of shale, rock, sandlayers, and other formations such as aquifers. A horizontal injectionwell 22, positioned several meters above in vertical alignment with aproduction well 24 is also drilled into the reservoir 12. In the presentmethodology, steam and solvent, injected through the injection well 22into the reservoir 12, flow from the injection well 22 into a vaporchamber 26 which develops during this, surrounding the injection well22. By injecting the fluids supra into the reservoir 12, heat andpressure are transmitted to the reservoir 12. The steam and solventeventually reach the edge of the vapor chamber 26 and contact the virginheavy oil or bitumen oil sand denoted by numeral 28. The steam releasesits latent heat and the solvent dissolves into the oil, both of whichreduce the viscosity of the heavy oil or bitumen which in turn, underthe action of gravity, mobilizes the viscosity-reduced heavy oil orbitumen to flow to the production well 10 which carries it to thesurface 14 by known techniques.

In FIG. 2, a typical injection and production profile for steam 30,solvent 32, and non-condensable gas 34 is displayed. At the start of theprocess, in stage 1, steam 30 is the major injectant flowing into thereservoir 12 from the injection well 22 that penetrates the reservoir12. In stage 1, the vapor chamber 26 is created in the reservoir 12.Also, as shown in FIG. 2A, the injection pressure, 8 is maintained assufficient to create the vapor chamber in the reservoir.

In stage 1, a small amount of solvent 32 or non-condensable gas 34 canbe co-injected with the steam 30 but if desired, steam 30 can beinjected alone into the reservoir 12 as is done in the SAGD process.After the steam chamber has formed, in stage 2, steam 30, solvent 32,and non-condensable gas 34 are injected together into the reservoir 12.One means of determining that a steam vapor chamber has formed is therequirement that continuous production of the heavy oil or bitumen isoccurring and that the ratio of the cumulative injected steam (expressedas cold water equivalent) to cumulative heavy oil or bitumen productionvolume (this ratio is called the cumulative steam to oil ratio, cSOR) isunder the value 4. This value of the cSOR implies that the heat from theinjected steam is reaching the heavy oil or bitumen at the edges of thechamber and that the mobilized bitumen is flowing under gravity drainageto the production well.

The amounts of the steam 30, solvent 32, and non-condensable gas 34 andthe injection pressure are chosen so that the solubility of the solventin the heavy oil and bitumen 36 is maximized. The addition of thesolvent improves heavy oil or bitumen mobilization beyond that only dueto heating because it dissolves in the heavy oil or bitumen, dilutes thehydrocarbon phase, and reduces its viscosity so that it can readily flowto the production well 32. A further benefit of solvent 30 addition tothe hydrocarbon phase is that it also dilutes the produced heavy oil orbitumen towards the specifications of fluid flow and density propertiesrequired for pipeline transport of the heavy oil or bitumen.

As the process evolves, the chamber 26 reaches the top of the reservoirand thereafter spreads laterally as shown in FIGS. 3A and 3B. As thechamber 26 grows, heat losses to the overburden 16 increase because thegreater exposed area of the heated vapor chamber 26 to the colderoverburden 16. To enhance the thermal efficiency of the recoveryprocess, in stage 2, the steam 30 injection rate is lowered and thesolvent 32 and non-condensable gas 34 injection rates are raised. Thesolvent 32 content in the injected fluids is between 1 and 80 volumepercent, preferably between 10 and 30 volume percent. The extent of thevapor chamber 26 is maintained by the increasing volume of solvent 31and non-condensable gas 32 injected into the reservoir 12.

Because the steam injection rate is reduced, the partial pressure of thesteam in the vapor chamber 26 falls and as a result the correspondingsaturation temperature of the steam drops and heat losses from the vaporchamber 26, in turn, are reduced because the temperature differencebetween the vapor chamber 26 and the overburden 16 is lowered. If theoverburden 16 temperature is higher than the vapor chamber 26, then heatpreviously lost to the overburden 16 is harvested back to the vaporchamber. This improves the overall efficiency of the process.Furthermore, as the temperature of the vapor chamber 26 falls, thesolubility of the solvent 32 increases in the heavy oil or bitumen 36.This leads to reduced viscosity of the heavy oil or bitumen 36 thatwould not have been possible without the solvent 32. Also, the additionof the non-condensable gas 34 helps to maintain or raise the operatingpressure which also enhances the solubility of solvent 32 into the heavyoil or bitumen 36. The relative amounts of the solvent 32 andnon-condensable gas 34 are chosen to maximize the effectiveness of thesolvent to reduce the viscosity of the heavy oil or bitumen and can bechosen from thermodynamic pressure-volume-temperature (PVT) andviscosity calculations.

The amount of injected solvent 32 is such that only sufficient solventis provided that is needed by the produced bitumen. This minimizes thebuild-up and storage of solvent 32 in the reservoir 12 which enhancesthe economic performance of the recovery process. As the process furtherevolves, the amount of solvent 32 and non-condensable gas 34 are reducedand con-currently, the injection pressure is reduced. This helps topromote production of the solvent 32 which enhances the economicefficiency of the process. At the end of the process, a blowdown stage(not shown) can be done to recover additional solvent and heavy oil orbitumen from the reservoir 12. Heavy oil or bitumen production from theproduction well is initiated during stage 1 and continues throughout therest of the process.

As the process evolves, the injection rates and injection pressure iscontrolled to result in the most economical recovery of heavy oil orbitumen and solvent 32.

The solvent 32 preferentially consists of one or a combination of C3+hydrocarbons, for example propane, butane, pentane, hexane, heptane,octane, nonane, and decane or any one or more components normallypresent in gas condensates or diluent. Preferably, the solvent 32 ishexane or heptane, or is a combination of C5 to C8 hydrocarbonsincluding any of the components that may normally be present in gascondensates or diluent. The non-condensable gas 34 preferentiallyconsists of C1 to C3 hydrocarbons, for example methane, ethane, andpropane, natural gas, or other gases such as carbon dioxide or any oneor more of the components normally present in the flue gas that resultsfrom combustion of a fuel to produce steam.

The solvent 32, non-condensable gas 34, and injection pressure arechosen so that the solvent 32 exist in substantially the vapor state atthe conditions of the reservoir but so that the solubility of thesolvent is maximized in the heavy oil or bitumen at the edges of thechamber 26.

Computer-aided reservoir simulation models can be used to predictpressure, oil, solvent, water, and gas production rates, and vaporchamber 26 dimensions to help design the injection strategy of thepresent invention. Also, the reservoir simulation calculations can beused to assist in the estimation of the length of stage 1 and 2 timeintervals.

Given that the steam injection rate falls during the process, theprocess yields reduced capital and operating costs that arise from theactivities surrounding steam 4 generation and water handling. Also,given that the solvent is introduced directly to the heavy oil orbitumen in the reservoir, there is inherent in situ upgrading dependingon the temperature and pressure evolution of the process.Advantageously, due to solvent addition in the reservoir, the amount ofdiluent needed to transport the heavy oil or bitumen once it is onsurface is reduced leading to reduced surface facilities requirements.Thus, the process delivers equal or more heavy oil or bitumen tocurrently known methods with higher thermal efficiency and economicperformance. With reduced steam usage, the process also has lessenvironmental pollution than current thermal recovery processes such asSAGD.

FIG. 4 is a plot that compares the cumulative steam to oil ratio (cSOR)from field scale numerical model predictions of the SAGD, ES-SAGD, andthe process of the present invention processes. The cSOR is a measure ofthe thermal efficiency of the process and is closely correlated with theeconomic performance of the recovery processes. The cSOR SAGD resultsare typical of results found in current field operations. The resultsshow that for the majority of the process life, the process of thepresent invention performance is substantially greater than that of theSAGD and ES-SAGD processes. FIG. 5 compares the cumulative oil produced(only contains oil component, no solvent) for the SAGD, ES-SAGD, andinventive processes. The results demonstrate that the process of thepresent invention produces more oil than the other processes. FIG. 6displays a representation of the cumulative solvent recovery of theES-SAGD and the instant processes. The results show that the injectionrate and pressure strategy of the present process yields significantlyhigher solvent recovery and thus higher economic performance of theprocess.

The process operated as described has improved economic benefit withrelatively high production at the start of the process, reduction ofheat injection after the process starts to lose heat to the overburdento improve thermal efficiency of the process after the overburden iscontacted, heated solvent injection to deliver diluted and possiblypartially upgraded heavy oil or bitumen to the production wellbore, andhigh solvent re-cycling capability to improve the economics of theprocess.

The embodiment(s) of the invention described above is(are) intended tobe exemplary only. The scope of the invention is therefore intended tobe limited solely by the scope of the appended claims.

1. A method for recovering heavy hydrocarbons from an undergroundreservoir containing heavy hydrocarbons, an injection well and aproduction well, comprising: a) injecting steam into said reservoir toform a steam vapor chamber; b) co-injecting predetermined quantities ofnon-condensable gas, hydrocarbon solvent and steam into said steam vaporchamber to maximize solubility of the solvent in said heavyhydrocarbons; c) recovering produced hydrocarbons within said productionwell; d) controlling the volume of said steam vapor chamber byprogressively adjusting the volume of said steam, said non-condensablegas and hydrocarbon solvent injected into said reservoir, whereby saidhydrocarbon solvent and non-condensable gas are predominant relative tothe volume of said steam; and e) recovering further produced heavyhydrocarbons.
 2. (canceled)
 3. The method as set forth in claim 1,wherein in step c) reservoir pressure is progressively increased.
 4. Themethod as set forth in claim 3, wherein reservoir temperature isprogressively lowered
 5. The method as set forth in claim 4, whereinsolvent solubility in said heavy hydrocarbons is increased.
 6. Themethod as set forth in claim 5, further including recovering saidhydrocarbon solvent.
 7. The method as set forth in claim 1, wherein saidhydrocarbon solvent comprises an alkane selected from the groupconsisting of C3 through C8 alkanes and mixtures thereof.
 8. The methodas set forth claim 1, wherein said hydrocarbon solvent comprises analkane derived from gas condensate.
 9. The method as set forth in claim1, wherein said hydrocarbon solvent comprises an alkane derived from gasdiluent.
 10. The method as set forth in claim 1, wherein saidnon-condensable gas comprises a gas selected from the group consistingof C1 through C3 hydrocarbons
 11. The method as set forth in claim 10,wherein said non-condensable gas comprises carbon dioxide.
 12. Themethod as set forth in claim 11, wherein said non-condensable gascomprises a gaseous component of flue gas.
 13. The method as set forthin claim 1, wherein said non-condensable gas is selected from the groupconsisting of C1 through C3 alkane hydrocarbons, carbon dioxide, acomponent of flue gas, natural gas and combinations thereof.
 14. Amethod for recovering heavy hydrocarbons from an underground reservoircontaining heavy hydrocarbons, an injection well and a production well,comprising: a) injecting steam into said reservoir, to form a steamvapor chamber; b) co-injectinag predetermined quantities of steam,hydrocarbon solvent and non-condensable gas into said steam vaporchamber to maximize the solubility of the solvent in said heavyhydrocarbons; c) recovering produced hydrocarbons through saidproduction well; d) determining the formation of said vapor chamber bycalculating the ratio of cumulative injected steam to cumulativehydrocarbon production volume; e) adjusting te volume of steam injectedinto said vapor chamber to be subordinate to the volume of hydrocarbonsolvent and non-condensable gas whereby partial pressure of said steamin said chamber is reduced and hydrocarbon solvent solubility iselevated in said heavy hydrocarbons; and f) recovering further producedhydrocarbons through said production well.
 15. (canceled)
 16. The methodas set forth in claim 14, further including the step of selecting thequantity of steam, non-condensable gas and injection pressure tomaximize the solubility of hydrocarbon solvent in said heavyhydrocarbons.
 17. (canceled)
 18. The method as set forth in claim 14,further including recovering said hydrocarbon solvent.
 19. A method forrecovering heavy hydrocarbons from an underground reservoir containingheavy hydrocarbons, an injection well and a production well, comprising:a) injecting steam into said reservoir, to form a steam vapor chamber,b) co-injecting predetermined quantities of steam, hydrocarbon solventand non-condensable gas into said steam vapor chamber to maximize thesolubility of the solvent in said heavy hydrocarbons, while controllingthe volume of said vapor chamber; c) recovering produced hydrocarbonsthrough said production well; d) adjusting the volume of steam injectedinto said vapor chamber to be subordinate to the volume of hydrocarbonsolvent and non-condensable gas whereby partial pressure of said steamin said chamber is reduced and hydrocarbon solvent solubility iselevated in said heavy hydrocarbons; and e) recovering further producedhydrocarbons through said production well.